It is well known that only a small fraction of the original oil in place in a petroleum reservoir can be recovered with so called "primary" and "secondary" production methods. Various "tertiary" methods of increasing the recovery of oil contained in oil-bearing rocks have been devised. Among these tertiary recovery techniques is the method of injecting a miscible compound into the reservoir. The most common miscible compound used is carbon dioxide (CO.sub.2).
In the initial stages of a CO.sub.2 flood, CO.sub.2 gas is commonly purchased from a large CO.sub.2 distribution pipeline. The price of gas purchased from these pipelines is presently in the range of $1.00 to $1.50 per thousand standard cubic feet (MSCF).
After injecting CO.sub.2 into the reservoir for a period of time, associated gas production will contain increasingly high percentages of CO.sub.2 due to breakthrough of the injected CO.sub.2 gas. It is often economical to recycle this gas into the petroleum reservoir. However, this recycled gas commonly has several undesirable components contained in it and it must be processed before reinjection. The primary constituents that must be considered in processing of this gas are methane (CH.sub.4) and nitrogen (N.sub.2) because these gases will dramatically reduce the miscibility of the injected gas. Other components that should be considered are heavier hydrocarbons (because of both their economic value as separate products and because of their ability to offset the miscibility problems created by CH.sub.4 and N.sub.2), H.sub.2 S (because of safety concerns and sales specifications), and water (because of hydrate problems).
Extensive efforts have been devoted to developing an economical method for treating these gas streams and a large number of process schemes have been devised.
Chemical solvents (such as amines) have been considered for removal of CO.sub.2 from the hydrocarbon components. Use of these solvents becomes impractical in gas streams containing high concentrations of CO.sub.2 because of the large energy demand of amine reboilers and other equipment. Further, the CO.sub.2 is saturated with water in amine plants and this can create hydrate and corrosion problems downstream.
Distillation of CO.sub.2 from methane has also been considered. The relative volatility of methane and CO.sub.2 is very high and this distillation is in theory quite easy. However, the process must operate at relatively high pressure and low temperature and, therefore, the possibility of a solid carbon dioxide phase coexisting with vapor/liquid CO.sub.2 /CH.sub.4 mixture is high. Solutions to this problem have been proposed in U.S. Pat. Nos. 4,318,723, 4,293,322 et al. in which an additive (generally natural gasoline recycled from elsewhere in the plant) is introduced into the feed. This prevents CO.sub.2 freezing and also aids in breaking an ethane/CO.sub.2 azeotrope. These processes have several inherent disadvantages, however. Initially, these processes are extremely expensive from both a capital and operating perspective since it is necessary to provide multiple distillation columns and massive refrigeration capacity to cool the entire inlet gas stream to -40.degree. F. or colder. For example, in the example labeled "Table II" in U.S. Pat. No. 4,318,723, the feed temperature is reduced to -65.degree. F. This also results in the need to use exotic materials of construction for the process equipment.
Further, the process produces sour, high vapor pressure liquid streams that must be subjected to additional processing before sale. Further, the ultimate value of the liquid products is offset by the need to purchase additional CO.sub.2 as a result of the lost gas volume, i.e., there is significant shrinkage associated with the process.
Simpler techniques for treating hydrocarbon rich CO.sub.2 streams have also been proposed in broad conceptual terms. For example, in "Looking at CO.sub.2 Recovery in Enhanced-Oil-Recovery Projects," Oil and Gas Journal, Dec. 24, 1984, the authors show a "Straight Refrigeration" process for separating hydrocarbons from CO.sub.2. However, this process also has several inherent disadvantages. Initially, as with the processes described in the above-mentioned patents, the inlet gas stream must be cooled to -40.degree. F. or colder for recovery of C.sub.3 +, requiring extremely high refrigeration capacity. Further, the liquid stream produced by this process would require further treatment before sale since it will have a high vapor pressure (approximately 40 psia RVP) as well as unacceptable CO.sub.2 and H.sub.2 S concentrations. Finally, a large portion of the C.sub.4 + would go overhead and be unnecessarily wasted since no rectification section is provided on the column.
In summary, it is desirable to create a process that recognizes the ability of ethane, propane and butane to overcome the negative effects of nitrogen and methane on the miscibility of CO.sub.2 injection gas. It is further desirable to create a process that produces both acceptable CO.sub.2 injection gas and saleable liquid products. It is further desirable to create a process that treats CO.sub.2 injection gas is an economical manner from both a capital investment and operating expense perspective. It is further desirable to create a process that does not require elaborate processing to overcome the CO.sub.2 /C.sub.2 H.sub.6 azeotrope or to avoid CO.sub.2 solid formation. It is further desirable to create a process which minimizes the shrinkage of the CO.sub.2 injection gas.